This invention relates to wellbore fluids, including drilling fluids, completion fluids, workover fluids, packer fluids, that is, all of those fluids which are employed over the course of the life of a well.
Generally wellbore fluids will be either clay-based or brines which are clay-free. These two classes are exclusive, that is, clay-based drilling fluids are not brines. A well-bore fluid can perform any one or more of a number of functions. For example, the drilling fluid will generally provide a cooling medium for the rotary bit and a means to carry off the drilled particles. Since great volumes of drilling fluid are required for these two purposes, the fluids have been based on water. Water alone, however, does not have the capacity to carry the drilled particles from the borehole to the surface.
In the drilling fluid class, clay-based fluids have for years preempted the field, because of the traditional and widely held theory in the field that the viscosity suitable for creating a particle carrying capacity in the drilling fluid could be achieved only with a drilling fluid having thixotropic properties, that is, the viscosity must be supplied by a material that will have sufficient gel strength to prevent the drilled particles from separating from the drilling fluid when agitation of the drilling fluid has ceased, for example, in a holding tank at the surface.
In order to obtain the requisite thixotropy or gel strength, hydratable clay or colloidal clay bodies such as bentonite or fuller's earth have been employed. As a result the drilling fluids are usually referred to as "muds". In other areas where particle carrying capacity may not be as critical, such as completion or workover, brine wellbore fluids are extensively employed. The use of clay-based drilling muds has provided the means of meeting the two basic requirements of drilling fluids, i.e., cooling and particle removal. However, the clay-based drilling muds have created problems for which solutions are needed. For example, since the clays must by hydrated in order to function, it is not possible to employ hydration inhibitors, such as calcium chloride, or if employed, their presence must be at a level which will not interfere with the clay hydration. In certain types of shales generally found in the Gulf Coast area of Texas and Louisiana, there is a tendency for the shale to disintegrate by swelling or cracking upon contact with the water if hydration is not limited. Thus the uninhibited clay-based drilling fluids will be prone to shale disintegration.
The drilled particles and any heaving shale material will be hydrated and taken up by the conventional clay-based drilling fluids. The continued addition of extraneous hydrated solid particles to the drilling fluid will increase the viscosity and necessitated costly and constant thinning and reformulation of the drilling mud to maintain its original properties.
Another serious disadvantage of the clay-based fluids is their susceptibility to the detrimental effect of brines which are often found in drilled formations, particularly Gulf Coast formations. Such brines can have a hydration inhibiting effect, detrimental to the hydration requirement for the clays.
A third serious disadvantage of clay-based drilling fluids arises out of the thixotropic nature of the fluid. The separation of drilled particles is inhibited by the gel strength of the drilling mud. Settling of the drilled particles can require rather long periods of time and require settling ponds of large size.
Other disadvantages of clay-based drilling fluids are their (1) tendency to prevent the escape of gas bubbles, when the viscosity of the mud raises too high by the incidental addition of hydratable material, which can result in blowouts; (2) the need for constant human control and supervision of the clay-based fluids because of the exceptable, yet unpredictable, variations in properties; and (3) the formation of a thick cake on the internal surfaces of the well-bore.
The brines have the advantage of containing hydration inhibiting materials such as potassium chloride, calcium chloride or the like. Quite apparently any solid particulate material would be easily separated from the brine solution since it is not hydrated. Thus, the properties of the brine are not changed by solid particulate matter from the wellbore. Similarly, since there is no opportunity for gas bubbles to become entrapped, blowouts are less likely in a clay-free brine-type wellbore fluid.
Recently it has been found that superior wellbore fluids having solid particle carrying capacity without gel strength could be prepared by employing a viscosifying amount of hydroxyethyl cellulose stabilized with magnesia in a brine. This is disclosed in greater detail in the copending patent application of Jack M. Jackson, S/N 101,177 filed Dec. 23, 1970, now abandoned, which is incorporated herein. Commercial embodiments of the discovery are available from several sources, for example, Brinadd Company, Houston, Texas, in an additive package sold under the name "Bex".RTM..
Thus, the wellbore art now has two competing and incompatible systems which can be used in a full range of wellbore operations, i.e., the problem plagued clay-based wellbore fluids or the improved clay-free brine wellbore fluids. In many areas of application, as noted above, clay-free brines are already the usual selection.
A common problem for both clay-based and clay-free brine wellbore fluids is water loss. A number of approaches have been employed to prevent water loss into the penetrated formation. For example, lignosulfonate salts are frequently employed for that purpose. Also oil has been employed as a water loss control agent.
Starch has been employed in both clay-free brine and clay-based wellbore fluids to aid in water loss control and under certain limited conditions it has been effective. However, in clay-free brine wellbore fluids serious drawbacks have been observed with starches. At temperatures around 300.degree. F. fluid loss control is abrogated, that is, the starch no longer provides any fluid loss control.
Another area where starches have proved unsatisfactory is in clay-free brine completion fluids, workover fluids and the like, where acid (generally HCL) is employed. The problem arises because the starches are not sufficiently acid soluble. This problem is particularly serious in injection wells where the insoluble starch can create pockets or block strata which the acid will not leach out, thus resulting in irregular injection into the formation when the well is employed for that purpose.
A particular problem encountered in using starch in clay-free brine wellbore fluids is the instability of the starches in the presence of calcium chloride brines. Generally, the starches begin to break down after about twenty four hours in the presence of calcium chloride.
Starch may undergo retrogradation which is a spontaneous tendency to associate and partially crystallize. The associated particles may precipitate and there appears to be a reverting to original cold water insolubility.
Thus although starches have been employed in clay-based fluids, they have generally not been successfully employed with the brine wellbore fluids. It is not surprising to note that the art has grouped all starches together and has considered the starch derivatives as no better or substantially equivalent to unmodified starches. Thus in U.S. Pat. No. 3,032,498 a cyanoethylated starch was described as a water loss reduction additive, which is not in itself surprising, however, brine-type fluids were excluded and a thin impervious layer was required to be formed on the wall by a thixotropic clay based mud.
It is a feature of the present invention to provide a fluid loss control additive for clay-free wellbore fluids having improved high temperature stability, improved acid solubility and improved stability in the presence of calcium chloride. It is also a feature of the present invention to provide a clay-free hydration inhibited brine wellbore fluid having improved fluid loss control at high temperatures, improved component solubility and longer useful life. It is a further feature of the present invention to provide a method for drilling porous subsurface formations and obtaining improved water loss control.
It is an advantage of the present invention that the fluid control component of the clay-free wellbore fluids is stable at temperatures above 300.degree. F., is acid soluble and is not adversely affected by other components of the clay-free wellbore fluids.
It is a further feature of the present invention to provide a clay-free brine drilling fluid having solid particle carrying capacity of a non-thixotropic type which is inhibited against hydration and which has improved fluid loss control at high temperatures, acid solubility and longer operation with constant fluid loss control. These and other advantages and features will be apparent from the following discussion and description of the invention and several of the embodiments thereof.